Influence of Asphaltene Aggregation and Pressure on Crude Oil Emulsion Stability

by

Inge Harald Auflem

Thesis Submitted in Partial Fulfilment of the

Requirements for the Degree of

DOKTOR INGENIØR

Department of Chemical Engineering

Norwegian University of Science and Technology

Trondheim, June 2002

Preface

Preface

This thesis, submitted in partial fulfilment of the requirements for the degree of dr.ing. at

the Norwegian University of Science and Technology, consists of five articles, one patent

and one book chapter. The thesis is based on work performed at Statoil Research Centre,

the Institute for Surface Chemistry in Stockholm, and Chalmers University of Technology

in Gothenburg in the period from August 1999 to June 2002.

My supervisor introduced me to the field of surface and colloid chemistry in 1997, while

studying physical chemistry as an undergraduate student at the University of Bergen.

Little did I then know that the work would lead me into the petroleum industry, and a

struggle with "the good and the bad asphaltenes". As an experimentalist, the work in the

laboratory has, more often than not, provided results difficult to interpret. Nevertheless,

the work has continued, and in-between the total failures, there has been some near

successes, which have resulted in the thesis you are now paging through.

During my time as a dr.ing. student I have had the fortune to participate in a project

with the acronym FLUCHA II, which stands for Fluid Characterisation at elevated

pressures and temperatures. The group has consisted of 3 dr.ing. students and 1 post

doc, under the guidance of the enthusiastic and demanding Prof. Sjöblom. The work

tasks of the group have covered a number of flow assurance related problems, i.e.

asphaltene precipitation, emulsion formation and stabilisation, naphthenate formation,

crude oil characterisation, etc.

i

Acknowledgements

Acknowledgements

First of all, I would like to express my sincere gratitude to my academic advisor Prof.

Johan Sjöblom, for his years of guidance and invaluable encouragement, along with

generous hosting when teambuilding throughout this research work.

During my three years of work, I have enjoyed the opportunity of working with several

fellow graduate students and postdoctoral associates, which have provided intellectual

assistance and an enjoyable working environment. I am also grateful to all my co-

authors, whom I have had the fruitful pleasure of collaborating with.

I would also like to acknowledge the FLUCHA II program financed by the Research

Council of Norway and the oil industry. Statoil ASA is especially thanked for providing

office space and access to laboratory equipment.

Finally, I wholeheartedly thank Helene and my parents for their love and support, without

which this work would never have been completed.

ii

Abstract

Abstract

Water-in-crude oil emulsions stabilised by various surface-active components are one of

the major problems in relation to petroleum production. This thesis presents results from

high-pressure separation experiments on "live" crude oil and model oil emulsions, as well

as studies of interactions between various indigenous stabilising materials in crude oil. A

high-pressure separation rig was used to study the influence of gas and gas bubbles on

the separation of water-in-crude oil emulsions. The results were interpreted as a flotation

effect from rising gas bubbles, which led to increased separation efficiency. The

separation properties of a "live" crude oil were compared to crude oil samples

recombined with various gases. The results showed that water-in-oil emulsions produced

from the "live" crude oil samples, generally separated faster and more complete, than

emulsions based on recombined samples of the same crude oil.

Adsorption of asphaltenes and resins onto a hydrophilic surface from solutions with

varying aromatic/aliphatic character was investigated by a quarts crystal microbalance.

The results showed that asphaltenes adsorbed to a larger degree than the resins. The

resins were unable to desorb pre-adsorbed asphaltenes from the surface, and neither did

they adsorb onto the asphaltene-coated surface. In solutions of both of resins and

asphaltenes the two constituents associated in bulk liquid and adsorbed to the surface in

the form of mixed aggregates. Near infrared spectroscopy and pulsed field gradient spin

echo nuclear magnetic resonance were used to study asphaltene aggregation and the

influence of various amphiphiles on the asphaltene aggregate size. The results showed

interactions between the asphaltenes and various chemicals, which were proposed to be

due to acid-base interactions. Among the chemicals used were various naphthenic acids.

Synthesised monodisperse acids gave a reduction of size of the asphaltene aggregates,

whereas polydisperse naphthenic acids seemed to affect the state of the asphaltenes only

to a minor extent. The effect of the naphthenic acids on the asphaltenes appeared

however, to depend on the asphaltene type. Other amphiphiles such as amines and

alcohols, showed a varying effect on the dispersion of the asphaltenes into smaller

aggregates. Furthermore, measurements of diffusion coefficients upon increased

concentration of asphaltenes, implied that the asphaltenes began to self-associate at

concentrations above 0.1 wt-% in toluene-d8.

iii

Table of Content

Table of Content

Preface ............................................................................................................... i

Acknowledgements............................................................................................... ii

Abstract ............................................................................................................. iii

Table of Content ................................................................................................. iv

List of Publications................................................................................................ v

Complimentary work ................................................................................ vi

1 Introduction............................................................................................. 1

2 Theory .................................................................................................... 3

2.1 Crude Oil Composition ................................................................... 3

2.2 Asphaltene Chemistry.................................................................... 4

2.3 Emulsions and Emulsion Stability .................................................... 9

2.4 Stabilisation of Water-in-Crude Oil Emulsions.................................. 10

2.5 Destabilisation of Crude Oil Emulsions............................................ 12

3 Methodology and Theory.......................................................................... 16

3.1 High-pressure High Temperature Separation Rig (HPHT-rig).............. 16

3.2 Quartz Crystal Microbalance (QCM)................................................ 18

3.3 Near Infrared Spectroscopy (NIR) ................................................. 20

3.4 Nuclear Magnetic Resonance (NMR) ............................................... 22

4 Main Results .......................................................................................... 26

4.1 Paper I ...................................................................................... 26

4.2 Paper II ..................................................................................... 28

4.3 Paper III.................................................................................... 33

4.4 Paper IV .................................................................................... 36

4.5 Paper V ..................................................................................... 37

4.6 Paper VI .................................................................................... 40

5 Summary and Conclusions ....................................................................... 44

References ........................................................................................................ 46

Papers I-VII

iv

List of Publications

List of Publications

1. Auflem, I.H., Kallevik, H., Westvik, A. and Sjöblom, J., Influence of Pressure and

Solvency on the Separation of Water-in-Oil Emulsions from the North Sea. Journal

of Petroleum Science and Engineering, 2001. 31(1): p. 1-12.

2. Kallevik, H., Sjöblom, J., Westvik, A., Auflem, I.H., Process for separation of water

and oil in a separator by breaking water-in-oil emulsions, P 4202-1, PCT-

application, 23. February 2002

3. Auflem, I.H., Westvik, A. and Sjöblom, J., Destabilisation of water-in-oil emulsions

based on recombined oil samples at various pressures. Journal of Dispersion

Science and Technology, Submitted

4. Ekholm, P., Blomberg, E., Claesson, P., Auflem, I.H., Sjöblom, J. and Kornfeldt,

A., A Quartz Crystal Microbalance Study of the Adsorption of Asphaltenes and

Resins onto a Hydrophilic Surface. Journal of Colloid and Interface Science, 2002.

247(2): p. 342-350

5. Auflem, I.H., Havre, T.E. and Sjöblom, J., Near Infrared Study on the Dispersive

Effects of Amphiphiles and Naphthenic Acids on Asphaltenes in Model Heptane-

Toluene Mixtures. Colloid and Polymer Science, In Press, 2002

6. Östlund, J.-A., Nydén, M., Auflem, I.H. and Sjöblom, J., Interactions between

asphaltenes and naphthenic acids. Energy & Fuel, Submitted

7. Sjöblom, J., Johnsen, E.E., Westvik, A., Ese, M.H., Djuve, J., Auflem, I.H. and

Kallevik, H., Demulsifiers in Oil Industry, in Encyclopedic Handbook of Emulsion

Technology, J. Sjöblom, Editor. 2001, Marcel Dekker, Inc.: New York. p. 595-619

v

List of Publications

Complimentary work

1. Johan Sjöblom, Einar Eng Johnsen, Arild Westvik, Linn Bergflødt, Inge H Auflem,

Trond E Havre and Harald Kallevik: Colloid Chemistry in Sub Sea Petroleum and

Gas Processing, Presented at: "The 2nd International Conference on Petroleum

and Gas Phase Behaviour and Fouling", Copenhagen, Denmark, August 27-31,

2000

2. Sjöblom, J., Kallevik, H., Aske, N., Auflem, I. H., Havre, T. E., Sæther, Ø. and

Orr, R.: Recent Development in the Understanding of the Stability and

Destabilization of Water-in-Crude Oil Emulsions, Presented at: "The 3rd

International Conference on Petroleum Phase Behavior and Fouling", New Orleans,

USA, March 10-14, 2002

3. Johan Sjöblom, Narve Aske, Inge Harald Auflem, Øystein Brandal, Trond Erik

Havre, Øystein Sæther, Arild Westvik, Einar Eng Johnsen, Harald Kallevik, Our

Current Understanding of Water-in-Crude Oil Emulsions. Recent Characterization

Techniques and High Pressure Performance, A Collection of Invited Papers in

Honour of Professor J.Th.G. Overbeek on the occasion of his 90th Birthday,

Advances in Colloid and Interface Science, In press, 2002

vi

Chapter 1 - Introduction

1 Introduction

In the North Sea, the hydrocarbon reserves include several marginal fields, which are

either small or deep-water fields. A feasible economical exploitation of these reserves

requires the introduction of subsea developments and multiphase fluid transport over

long distances. This has made it extremely important to reliably predict and control fluid

behaviour, in order to minimise the need for additional process installations or costly well

interventions. Typical problems that may occur are deposition of organic matter in

reservoir and process equipment, and the formation of stable water-in-crude oil

emulsions when co-produced water and oil are mixed through chokes and pipelines.

The heaviest and most polar fraction of the crude oil is named asphaltenes, and gives

rise to a variety of nuisances during crude oil production. It is widely recognized that

flocculation and deposition of asphaltenes may occur when the thermodynamic

equilibrium is disturbed. This may come as a result of changes in pressure and

temperature [1-3], as a result of compositional alterations when blending fluid streams

[4], or due to injection of gas during improved oil recovery (IOR) operations. The most

serious precipitation problem is the creation of a formation damage [5], i.e. partial or

complete blockage of the inflow zone around a well, and thereby loss of productivity.

Another possible problem is adsorption of asphaltenes on to the reservoirs mineral

surfaces, whereby the wettability of the reservoir is changed from water-wet to oil-wet

[6] and thereby reducing the potential oil recovery. In addition, the asphaltenes may

deposit on the steel walls in the production line, or be transported along in the pipeline

only to accumulate in separators or other fluid processing units. Clean up of deposited

asphaltenes in the field may necessitate well shut-in and loss of oil production. Hence,

preventing asphaltene flocculation is preferable from both an operational and economical

viewpoint.

During oil production and transportation, the water and oil phases are co-produced, and

thereby exposed to sufficient mixing energy to form dispersions of water droplets in oil

and, conversely, oil droplets in the water. Unfortunately, the crude oil contains a number

of components, which are interfacially active in nature, i.e. asphaltenes, resins and

naphthenic acids. These components may accumulate at the water-oil interface and

hinder the droplets from re-forming a separate phase. Among these components,

asphaltenes are believed to be the major material involved in emulsion stabilisation.

1

Chapter 1 - Introduction Asphaltenes tend to adsorb at water-in-crude oil interfaces to form a rigid film

surrounding the water droplet, thereby protecting the interfacial film from rupturing

during droplet-droplet collisions [7-11]. Hence, the formation of extremely stable water-

in-crude oil emulsions is facilitated. This results in a demand for expensive emulsion

separation equipment such as separators, water treaters and coalescers. However, with

reliable information concerning the crude oil and its emulsifying properties, steps can be

taken in pre-treating the crude oils with destabilising chemicals, or by installing

equipment specifically designed for each field, to avoid emulsion problems.

2

Chapter 2 - Theory

2 Theory

This chapter contains theory and references related to the topics discussed in this thesis.

The theoretical consideration is primarily concerned with the formation, stabilisation, and

destabilisation of crude oil emulsions, as well as the chemistry behind the natural

surfactants responsible for stabilising the emulsions.

2.1 Crude Oil Composition

Crude oil is a complex mixture of hydrocarbons, with small amounts of sulphur, oxygen

and nitrogen, as well as various metallic constituents, particularly vanadium, nickel, iron

and copper [12]. A typical North Sea Crude Oil consists of 84.5 % carbon, 13 %

hydrogen, 0.5 % nitrogen, 1.5 % sulphur and 0.5 % oxygen. The number of single

components that exist in a crude oil is unknown. To determine the exact structure and

composition of the various components is thus a daunting task, and the selection of

fractionation procedure depends on the information desired.

The asphaltene content of petroleum is an important aspect of fluid processability. The

SARA method, where the asphaltenes are separated as a group, is therefore often used

to conveniently separate the crude oil into four major fractions: saturates (including

waxes), aromatics, resins and asphaltenes (SARA), based on their solubility and polarity

as shown in Figure 2-1.

Figure 2-1 Typical scheme for separating crude oil into saturate, aromatic, resin and asphaltene

(SARA) components.

3

Chapter 2 - Theory The basis for the method is that asphaltenes are removed by precipitation in a paraffinic

solvent, and the deasphalted oil is separated into saturates, aromatics and resins by

chromatographic fractionation [13-17]. Of the four classes of compounds, only the

saturates are easily distinguishable from the rest of the hydrocarbons in the mixture. The

absence of π-bonds allows them to be readily differentiated from the aromatic

components by virtue of the difference in their polarities. The remainder of the oil is

composed of aromatics and heteroatomic compounds of varying degree of condensation,

alkyl substitution and functionalism, which constitute a compositional continuum with

respect to molecular weight and polarity [18]. The many variations in the recommended

procedures, may all have some influence upon yield and chemical nature of the fractions.

The properties of asphaltenes, for example, have shown to be affected by temperature,

precipitating solvent, solvent-to-oil ratio and separation time [19].

2.2 Asphaltene Chemistry

The word asphaltene was coined in France by Boussingault [20] in 1837. Boussingault

described the constituents of some bitumens found at that time in eastern France and in

Peru. He named the fraction of distillation residue, which was insoluble in alcohol and

soluble in essence of turpentine, “asphaltene”, since it resembled the original asphalt.

The strong interest in developing a better understanding of the solution behaviour of

asphaltenes, has been motivated by their impact on production, transportation, refining

and utilization of petroleum. The asphaltene fraction is composed of the heaviest and

components in crude oils. Separated solid asphaltenes usually appears brown to black in

colour and has no definite melting point but decomposes when the temperature exceeds

300-400 °C. It has been shown that changes in temperature [21, 22], pressure [1, 23-

25] and oil composition [26] can cause asphaltene precipitation.

Asphaltenes are operationally defined as the non-volatile and polar fraction of petroleum

that is insoluble in n-alkanes (i.e. pentane or heptane). As a result, asphaltenes

constitute a solubility class of crude oil components, rather than a chemical class. The

molecular weight, polarity and aromaticity of precipitated asphaltenes generally increase

with increasing carbon number of n-alkane precipitant. A schematic diagram representing

the range of heavy compounds precipitated by mixing crude oil with n-pentane and n-

heptane is shown in Figure 2-2.

4

Chapter 2 - Theory

Figure 2-2 Hypothetical diagram representing the molecular characteristics of the asphaltenes

precipitated from petroleum by n-alkane addition [27, 28].

A number of investigators have constructed model structures for asphaltenes, resins, and

other heavy fractions based on physical and chemical methods. Physical methods include

IR, NMR, ESR, mass spectrometry, X-ray, ultra-centrifugation, electron microscopy, small

angle neutron scattering, small angle X-ray scattering, quasi-elastic light scattering

spectroscopy, VPO, GPC, etc. Chemical methods involve oxidation, hydrogenation, etc.

While asphaltenes are recognised to be remarkably polydisperse in heteroatomic

functionality, molecular weight, and carbon backbone structure, some common features

have been established. Asphaltenes are characterized by fused ring aromaticity, small

aliphatic side chains, and other elements including sulphur, oxygen, nitrogen, and metals

such as vanadium and nickel. The heteroatoms accounts for a variety of polar groups

such as aldehyde, carbonyl, carboxylic acid and amide, which are found in the asphaltene

molecules. The aromatic carbon content of asphaltenes is typically in the range of 40 to

60 %, with a corresponding H/C atomic ratio of 1.0-1.2. A large percentage of these

aromatic carbon rings are interconnected in the molecular structure and, consequently,

the asphaltene molecule appears flat or planar. Figure 2-3 shows a suggested asphaltene

structure. Yen and co-workers [29, 30] proposed a macrostructure model, where the

asphaltenes was depicted as stacks of flat sheets of condensed aromatic systems, which

was interconnected by sulphide, ether, of aliphatic chains. Espinat et al. [31] suggested

the asphaltene molecules to be disc-like with polyaromatic fused ring cores containing

polar functional groups. It is currently accepted that asphaltenes consist of aromatic

compounds with π-π interactions, which undergo acid-base interactions and self associate

through hydrogen bonding [32, 33].

5

Chapter 2 - Theory

Figure 2-3 Hypothetical molecular structure of the asphaltenes. By courtesy of the Statoil DART

(Downhole Asphaltene Remediation Technology) program.

Several major problems associated with the recovery and refining of petroleum [34-39],

are related to the aggregation and precipitation of asphaltenes. Investigations have

shown that asphaltene particles may self-associate, and form aggregates in the presence

of aromatic hydrocarbons [26]. The degree of association is largely dependent upon the

aliphatic/aromatic ratio of the solvent. Due to the aggregation phenomena,

measurements of the true molecular weight and the aggregate size are inherently

difficult and have resulted in numerous research efforts. The size of the aggregate

structure has been suggested to lie between 2 and 25 nm in diameter [40-42]. The

molecular weight obtained have ranged from a few hundred to several million gmol-1,

however, the most recent values from several different types of asphaltenes tend to

suggest values from 600-1500 gmol-1 [43-49].

The aggregation is thought to occur through hydrogen bonding, however there is some

inconsistency in the description of asphaltene self-association [30, 50-52], and both

micelles and colloids are used in reference to asphaltenes. An asphaltene colloid is

defined as a submicron particle consisting of several asphaltene molecules bound by π-

bond interactions between polyaromatic clusters. Asphaltene micelles are considered

analogous to a surfactant micelle, where the association of molecules is driven by

hydrophobic-hydrophilic interactions. The terms “aggregate” and “micelle” are often used

interchangeably in the literature. It has been shown that resins are essential in dissolving

the asphaltenes in the crude oil. They are thought to attach to the asphaltene

micelles/aggregates with their polar groups, and stretch their aliphatic groups outward to

form a steric-stabilisation layer around asphaltenes [53, 54]. However, there still remains

6

Chapter 2 - Theory the debate about whether the micelle in petroleum is homogeneous insofar as it is

composed only from asphaltenes, or if both asphaltene and resin molecules constitute a

mixed micelle [30, 54].

Resins are defined as the non-volatile and polar fraction of crude oil that is soluble in n-

alkanes (i.e., pentane) and aromatic solvents (i.e., toluene) and insoluble in liquid

propane. They are structurally similar to asphaltenes, on the other hand, molar mass is

lower, hydrogen/carbon ratio higher, and the heteroatom content lower. Long et al. [28]

showed that once resins were removed from the crude by adsorption chromatography,

the remaining oil phase could no longer stabilise the asphaltenes.

Asphaltenes are also known to self-associate due to pressure depletion [1-3, 55]. At high

pressures in the reservoir, the asphaltenes are dissolved in the monophasic crude oil.

When the pressure is reduced the molar volume and the solubility parameter difference

between asphaltenes and the crude oil increases towards a maximum at the bubble point

of the crude oil. As a result of the reduced solvating power, the asphaltenes may start to

precipitate at some onset pressure higher than the bubble point. Prior to the precipitation

a stepwise association of the asphaltene molecules will take place. The final precipitation

is due to a strong attraction between the colloidal particles and the formation of

agglomerates. Once gas evolves, the light alkane fraction of the liquid phase is reduced,

and thereby the solvating power for asphaltene molecules increases. The relative change

in asphaltene solubility has been shown to be highest for light crude oils that are

undersaturated with gas, and which usually contain only a small amount of asphaltenes.

This gives the surprising result that light reservoir oils, which are low in asphaltenes are

considered to be more likely to experience asphaltene related field problems than

heavier, less undersaturated, asphaltenic oils.

A possible way of avoiding asphaltene precipitation is by adding chemicals that act in a

way similar to resins by dispersing the asphaltenes in solution. Gonzales et al. [56]

investigated the peptization of asphaltenes in aliphatic solvent by various oil-soluble

amphiphiles including long-chain alkylbenzene, alkyl alcohol, alkylamine and p-

alkylphenol. They found that the head group of the amphiphile influenced the

effectiveness of the amphiphiles. Chang and Fogler [32, 33], using a series of

alkylbenzene-derived amphiphiles as the asphaltene stabilisers, investigated the

influence of the chemical structure on the asphaltene solubilisation and the strength of

7

Chapter 2 - Theory the amphiphile-asphaltene interactions. The results showed that the polarity of the

amphiphile head group and the length of the alkyl tail controlled the amphiphile

effectiveness. Increasing the acidity of the amphiphile head group could promote the

amphiphile ability to stabilise asphaltenes, probably through acid – base interactions

between the asphaltene and the amphiphiles. León et al. [57] showed results from

adsorption studies on asphaltene particles, where the adsorption isotherms of two

amphiphiles (nonylphenol and nonylphenolic resin) were compared to a native resin. The

adsorption isotherm for the natural resins was characterised by the continuous increase

in the amount of adsorbed resins, and there was no indication of a plateau similar to the

ones shown by the amphiphiles. This type of isotherm was explained by the penetration

of substrate micropores by resin molecules, which lead to the partial breakdown of the

asphaltene macrostructure.

In addition to the resins, other molecules in the petroleum mixture have also shown a

tendency to stabilise the asphaltene particles/aggregates. Auflem et al. [58] showed that

natural and synthetic naphthenic acids have a tendency to disperse the asphaltenes, and

reduce the asphaltene particle size. This was proposed to occur through acid-base

interactions between the naphthenic acids and asphaltenes, whereby the naphthenic acid

would disperse the asphaltenes in solution in a similar way as the resins.

Naphthenic acids are classified as monobasic carboxylic acids of the general formula

RCOOH, where R represents a cycloaliphatic structure. The classification contains a wide

variety of structures with carbon number from C10 to C50, and from 0 to 6 saturated rings

[59]. In crude oil production, the problems related to naphthenic acids arise from the

processing conditions. As the pressure drops during production and carbon dioxide is lost

from solution, the pH of the brine increases, which in turn leads to dissociation of the

naphthenic acid (RCOOH → RCOO- + H+). As a result, the following may occur: i)

deposition of naphthenates [60] in oil/water separators, de-salters, tubing or pipelines

following complexation of naphthenic acids with metal cations present in the aqueous

phase and, ii) formation of stabilised emulsions due to naphthenic acids and

naphthenates accumulating at the w/o interface [61] and thereby stabilising colloidal

structures.

8

Chapter 2 - Theory 2.3 Emulsions and Emulsion Stability

Emulsions have long been of great practical interest due to their widespread occurrence

in everyday life. They may be found in important areas such as food, cosmetics, pulp &

paper, pharmaceutical and agricultural industry. Emulsions are also found in the

petroleum industry, where they are typically undesirable and can result in high pumping

costs, reduced throughput and special handling equipment. An emulsion is usually

defined as a system consisting of a liquid dispersed in another immiscible liquid, as

droplets of colloidal sizes (~ 0.1-10 µm) or larger. If the oil is the dispersed phase, the

emulsion is termed oil-in-water (o/w) emulsion, conversely, if the aqueous medium is the

dispersed phase, it is termed a water-in-oil (w/o) emulsion. This classification is not

always appropriate and other types as, for instance, multiple emulsions of the type

o/w/o, may also be found. In the emulsified state, the interfacial area between the

dispersed droplets and the bulk phase represents an increase in the systems free energy.

Consequently, the emulsions are not thermodynamically stable, and will seek to minimise

the surface area by separating into the different phases. For an emulsion to separate, the

droplets must merge with each other, or with the homophase continuum that gradually

forms.

Processes that facilitate the separation are sedimentation/creaming, flocculation and

coalescence [62-64], as shown in Figure 2-4. Creaming and sedimentation create a

droplet concentration gradient due to a density difference between the two liquid phases,

which result in a close packing of the droplets. Aggregation of droplets may be said to

occur when they stay very close to one another for a far longer time than if there were

no attractive forces acting between them. The size and shape of the individual droplets

are for the most part retained. The mechanism of coalescence occurs in two stages; film

drainage and film rupture. In order to have film drainage there must be a flow of fluid in

the film, and a pressure gradient present. However, when the interfacial film between the

droplets has thinned to below some critical thickness, it ruptures, and the capillary

pressure difference causes the droplets to rapidly fuse into one droplet. Hence, the

properties of the thin film are of uttermost importance for the separation. If the droplets

deform, the area of the interface increases and consequently the drainage path in the

film also increases, resulting in lower drainage rates.

Electrical double layer repulsion, or steric stabilisation by polymers and surfactants with

protruding molecular chains, may prevent the droplets to come into contact with each

9

Chapter 2 - Theory other. Also, polymers, surfactants or adsorbed particles can create a mechanically strong

and elastic interfacial film that act as a barrier against aggregation and coalescence. A

film of closed packed particles has considerable mechanical strength, and the most stable

emulsions occur when the contact angle is close to 90º, so that the particles will collect

at the interface. Particles, which are oil-wet, tend to stabilise w/o emulsions while those

that are water-wet tend to stabilise o/w emulsions. In order to stabilise the emulsions the

particles should be least one order of magnitude smaller in size than the emulsion

droplets and in sufficiently high concentration.

Other factors that usually favour emulsion stability are low interfacial tension, high

viscosity of the bulk phase and relatively small volumes of dispersed phase. A narrow

droplet distribution of droplets with small sizes is also advantageous, since polydisperse

dispersions will result in a growth of large droplets on the expense of smaller ones, an

effect termed Ostwald ripening [65]. Special features of surfactant association into liquid

crystalline phases with lamellar geometries that facilitates the stabilisation may also

occur [66].

Figure 2-4 Processes taking place in an emulsion leading to emulsion breakdown and separation.

2.4 Stabilisation of Water-in-Crude Oil Emulsions

The oil industry has an interest in crude oil emulsions for two main reasons: i) Water-in-

crude oil emulsions can form in the processing of fluids from hydrocarbon reservoirs to

10

Chapter 2 - Theory the refinery or in production facilities during extraction and cleaning. The emulsified

water adds significant volume to the crude oil, causes corrosion in the pipelines and

increases the cost of transportation and refining. ii) Water-in-crude oil emulsions can

form in oceanic spills. These emulsions are very stable and the oil phase is difficult to

recover, leading to great environmental damage. Due to their colour and semisolid

consistency, they are often named chocolate mousse.

In order to devise optimum treatment for water-in-oil emulsions, it is vital to understand

how they are stabilised. The predominant mechanism whereby petroleum emulsions are

stabilised, is through the formation of a film with elastic or viscous properties. This film is

thought to consist of a physical, cross-linked network of asphaltenic molecules, which

aggregate through lateral intermolecular forces to form primary aggregates or micelles at

the oil-water interface [8, 9, 67-73]. In addition, adsorption of solid particles from wax,

clays, inorganic material or naphthenates may contribute to the film strength. Hence, the

emulsion stability arises from a physical barrier that hinders the film to break when

insufficient energies are involved in collisions between droplets.

Asphaltenes are thought to be peptised in the oil phase by the resinous components, and

are hence prevented from precipitation. However, when water is introduced to the crude

oil, the asphaltenic aggregates in the oil phase adsorbs to the new oil-water interface.

The resins are likely shed and do not participate in the stabilising film [74], Figure 2-5.

Eley et al. [75] showed that the stability of water-in-crude oil emulsions was related to

the asphaltene precipitation point. The most stable emulsions occurred when the

asphaltenes were on the verge of precipitation or above.

Kilpatrick et. al [74] have shown that the resins are unnecessary in the stabilisation of

the asphaltenic film. The exact conformation in which asphaltenes organize at oil-water

interfaces and the corresponding intermolecular interactions have yet to be agreed upon.

The often suggested explanations are either H-bonding between acidic functional groups

(such as carboxyl, pyrrolic and sulfoxide), electron donor-acceptor bonding between

transition metal atoms and electron-rich polar functional groups, or some other type of

force such as π-bonding between delocalised π electrons in fused aromatic rings. The

relative strength and importance of each in forming the viscoelastic film and their

consequent roles in stabilising water-in-oil emulsions have still not been fully explained.

11

Chapter 2 - Theory

Figure 2-5 Proposed stabilising mechanisms for asphaltenes in petroleum by resin molecules.

Asphaltene aggregates shed solvating resins and adsorb to oil-water interface through polar

interactions and hydrogen bonding [76].

2.5 Destabilisation of Crude Oil Emulsions

The destabilisation of crude oil emulsions forms an integral part of crude oil production.

Stable emulsions are typically broken using gravity or centrifugal settling, application of

high electric fields and addition of destabilising chemicals (demulsifiers). Other methods

such as pH adjustment, filtration, membrane separation and heat treatment techniques,

may also be used.

Gravity settling tanks, cyclones, centrifugal separators and other kinds of mechanical

separation tools are typical equipment used in the destabilisation of crude oil emulsions.

However, this hardware is of considerable volume as well as expensive to install on

offshore platforms typical for North Sea conditions. It is therefore of great economical

benefit whenever the installations can be kept at a minimum in size and number.

Chemical destabilisation is therefore a very common method for destabilising emulsions.

Also, the capital cost of implementing or changing a chemical emulsion-breaking program

is relatively small and can be accomplished without a shutdown. The separation rate of a

12

Chapter 2 - Theory w/o emulsion depends upon the matching of the demulsifier with the process residence

time, the concentration and the stability of the emulsion, the temperature, the process

vessel, the mixing energy and the type of stabilising mechanisms. Through building up

more fundamental knowledge concerning the processes involved in stabilising and

breaking the emulsions, the development and use of environmentally friendlier chemicals

is facilitated. Also, the optimisation of type and amount of chemicals employed,

contributes to reducing the oil content in the produced water offshore.

Commercial demulsifiers are typically mixtures of several components, which have

various chemical structures and cover a wide molecular weight distribution. Some typical

chemical structures used as demulsifiers are listed by Jones et al. [77] and Djuve et al.

[78]. Each component of the demulsifier typically possesses a different partitioning ability

and a different interfacial activity, and thus should provide a range of properties such as:

i) Strong attraction to the oil/water interface, with the ability to destabilise the protective

film around the droplet. ii) The ability to function as a wetting agent, changing the

contact angel of solids. iii) The ability to act as flocculants and, iv) promotion of film

drainage and thinning of the interdroplet lamella by inducing changes to the interfacial

rheological properties such as decreased interfacial viscosity and increased

compressibility [73, 79, 80]. Krawczyk [81] showed that demulsifiers with equal

partitioning between the aqueous and oil phase, gave the best destabilising efficiency.

This balance would lead to a maximum in the surface adsorption of demulsifier and a

minimum in interfacial tension. However, partitioning would not be a dominant factor

when other effects such as dissolution of the interfacial material or their flocculation by

the demulsifier occur.

When two water droplets approach each other, the capillary pressure acting normal to

the interface causes liquid to be squeezed out of the film into the bulk. This liquid flow

results in a viscous drag on the surfactants in the sublayer, and the adsorbed emulsifier

are carried away towards the film periphery, thereby creating a nonuniform concentration

distribution. Demulsifier molecules may then occupy the empty spaces available for

adsorption, and due to the high interfacial activity of the demulsifier, the interfacial

tension gradient is reduced. This leads to a strong increase in the rate of film thinning,

and ultimately, when the film thickness decreases below some critical value, the film

ruptures and the droplets coalesce.

13

Chapter 2 - Theory Strong attraction to the oil/water interface is often dependent on diffusibility and

interfacial activity of the demulsifier. For fast diffusion to the interface, the molecular

weight of the demulsifier becomes important. The demulsifiers relative solubility in oil is

also important for mass transport to the interface, and where this is inadequate, carrier

solvents (e.g. alcohols or benzene derivatives) are often used. At the interface, the

demulsifier may influence the droplet interfacial film material by displacement,

complexation, changing the solubility in the continuous phase, changing the viscosity of

the interfacial film, or through quick diffusivity and adsorption, thus inhibiting the Gibbs-

Marangoni effect, which counteracts film drainage.

In residual emulsions, the droplets are finely dispersed and widely distributed, and the

flocculating ability of the demulsifier is required to gather up the droplets. Then, high

molecular weights highly branched demulsifiers, with an affinity for the water droplet, are

necessary. For emulsions with particle-stabilised films, demulsifiers, which act as wetting

agents, may prove effective. The demulsifier may adsorb on to the solids, causing them

to be more oil or water wettable, and thereby more easily transported into the

continuous phase away from the interface. In some situations the demulsifiers have been

used as inhibitors, i.e. injected before the emulsification process has taken place. This

gives the demulsifier the chance to compete with the emulsifying agent in the process of

covering the interface as the emulsifying process occurs, and thereby hinder the

formation of a stabilising film. One should however, not forget to clarify the effect of

concentration of the injected chemicals on the emulsion stability, as too much chemicals

injected may result in an overtreat where the emulsion is actually stabilised, or a new

emulsion type is created. Also, the injected demulsifiers should be checked to be

compatible with other chemicals (corrosion inhibitors, scale inhibitors and flow

enhancers) used in the stream as well as the components in the produced stream itself.

The effect of increased temperature is the sum of changes in several parameters. For

instance, changes in the solubility of the crude oil surfactants or injected treating

chemicals may occur as a result of increasing temperature. The density of the oil is

reduced faster than the density of water as temperature increases, thereby accelerating

the settling. Bulk viscosity of the crude oil decreases with increasing temperature, hence

facilitating an increased collision frequency between water droplets, in addition to

increasing the settling rate. Essential for the coalescence, especially in flocculated

systems, is the influence of the interfacial viscosity. Depending on the type of interface

the interfacial viscosity may decrease, increase or remain unchanged with increased

14

Chapter 2 - Theory temperature [77]. With highly paraffinic crudes found in the North Sea, waxes are

strongly correlated to the stability of emulsions. The wax may contribute to the stability

through particle stabilisation, or from increasing the viscosity of the crude oil. Therefore,

melting and crystallisation sequence of wax is of importance for the stabilising properties

of these compounds [82]. High operational temperatures may however result in high

losses of light end molecules, and consequently an increased potential for asphaltene

deposition.

Electrical resolution of crude oil emulsions is possible since the systems are relatively

non-conducting. In 1965 Waterman [83] summarised the main behaviours of a drop, or a

pair of drops under an electric field. The mechanism promoting separation are the result

of either forces between particles resulting from induced dipoles charges (dipole

coalescence), or forces that result from interactions between unidirectional field and

particles having a net charge (electrofining). The principle behind the electrically induced

coalescence is often divided into: i) non interacting droplets approaching each other, ii)

deformation of droplets and formation of plane-parallel films, and iii) thinning of the films

to a critical thickness at which the film becomes unstable, ruptures and the two drops

unify and form a single large droplet. Important features of a typical electrocoalescer

are: The electric field (AC or DC), frequency, and set up for electrodes. The

electrocoalescers in the oil and petroleum industry uses both AC and DC electric fields for

the separation of water-in-oil emulsions [84]. One problem is that most of the equipment

in the marked today is big and bulky, and it would therefore be of interest to develop

small portable devices, incorporating features such as an optimum applied field strength

combined with centrifugal force, to further enhance the separation.

15

Chapter 3 - Methodology and Theory

3 Methodology and Theory

In the following section, a summary of the various methods utilised in this thesis, is

presented. A high-pressure separation rig is used in paper I-III, the quartz crystal

microbalance technique is found in paper IV. In Paper V and VI, respectively, near

infrared spectroscopy and nuclear magnetic resonance is employed.

3.1 High-pressure High Temperature Separation Rig (HPHT-rig)

In order to study separation of emulsions under realistic conditions, a high-pressure

separation rig has been constructed at Statoil’s R&D Centre. The rig can be used to

prepare emulsions and monitor the separation of oil and water, as well as any stable

foam formation, in a vertical batch separation cell. The separator cell is made from

sapphire assuring full visibility of the separation processes, it has a volume of 0.5 litres

and tolerates pressures up to 200 bar. A schematic drawing of the rig is presented in

Figure 3.1. The rig includes four 600 ml high-pressure sample cylinders. With the aid of

four motor driven high capacity piston pumps, water and oil are pumped from the sample

cylinders, through the choke valves and into the separator. The four pumps can be

controlled independently, however, the total flow rate is usually kept constant. Pressure

drop through the choke valves are back-pressure controlled. In order to control the

separation pressure, the separation cell is pressurised with gas, inert or natural gas, and

the pressure is regulated by another back-pressure controlled valve. To ensure

temperature control of the system, a thermostated cabinet encloses the separation cell

and provides temperatures in the range of –7 °C to 175 °C.

The principle of the rig is that flows of two pressurized fluids meet and stream through a

choke valve (VD2 or VD3). The streams from VD2 and VD3 meet in a third choke valve,

VD1, before entering a vertical batch separator. As the fluid mixture passes through the

choke valves it undergoes pressure drops, which provides the shear force necessary to

create more interface between the oil and water phases, thereby forming water droplets

in the oil phase.

16

Chapter 3 - Methodology and Theory

Figure 3.1 Schematic view of the high-pressure separation rig.

If the pressure drops below the bubble point pressure of the oil, a gaseous phase

appears. The gas evolved may form a foam layer, as well as influence the settling and

coalescence of water droplets. The quantity of the different phases, foam, oil, emulsion

layer and water, can thereafter be recorded as a function of time. To aid in the

monitoring process, video cameras have been connect to the rig. Samples of oil, water

and emulsion layer may be sampled by connecting a pipeline to the bottom of the

separator cell. To study the effect of emulsion and foam inhibitors or demulsifiers, the rig

is equipped with two independent high precision pumps (5 and 6), which deliver volumes

down to 0.03 mlh-1. Low concentration chemicals can thus be injected to any of the flow

lines. Injections can also be made in the bottom of the cell, where a stirrer can be used

to distribute the chemicals.

The high-pressure separation rig is a batch separator, and the results will therefore not

apply exactly for a field separation process. Nevertheless, the results will show trends for

temperature, pressure, pressure-drop, mixing with other oils, etc. It will also indicate

whether there is a need for chemical treatments (demulsifier, foam inhibitor etc).

Comparisons of field tests and laboratory studies of the separation of oils have shown

that the high-pressure separation rig give the same ranking of the oils, the same ranking

of the demulsifiers efficiency and the same optimum demulsifier concentration as in the

field tests. It should also be noted that bottle tests did not give the same ranking of the

chemicals as the field tests and the separation rig experiments.

17

Chapter 3 - Methodology and Theory 3.2 Quartz Crystal Microbalance (QCM)

The first thorough investigation of the piezoelectric effect is often attributed to Jaques

and Pierre Curie, as early as 1880 [85]. However, it was not until 1917 when Langevin

[86] showed that quartz crystals could be used as transducers and receivers of

ultrasound in water, that a more detailed study of piezoelectricity started. In 1959,

Sauerbrey [87] published a Paper showing that the frequency shift of the quarts crystal

was proportional to the added mass. This signified the birth of a new quantitative method

for measuring very small masses, i.e. the quartz crystal microbalance. Another important

step was a Paper by Nomura and Okuhara [88], where QCM was proven reliable for

measurements in the liquid phase. Preferably, one side of the sensor should be exposed

to the liquid, and the other to the gas phase. At present, the QCM technique is in rapid

expansion, and has found a wide range of applications in areas such as food,

environmental and clinical analyses [89].

The conventional quartz crystal microbalance, QCM, consists of a thin disk of piezoelectric

quartz crystal, which can be used to measure very small masses. The crystal is

sandwiched between a pair of electrodes, which are hooked up to an electronic oscillator.

When an AC voltage is applied over the electrodes, the crystal can be made to oscillate at

its resonance frequency, f, via the piezoelectric effect. However, the oscillatory motion is

damped due to i) energy losses in the crystal, ii) energy losses due to deposited material

on the sensor, and iii) energy losses to the surrounding medium. The magnitude of these

losses can be measured by suddenly switching off the driving field to the sensor crystal

and monitor the oscillation which will rapidly decay in amplitude in the form of a damped

sinusoidal wave, characterised by the frequency, f, and the time constant, τ, for the

damping. The latter factor is inversely proportional to the sum of dissipative

mechanisms, termed the dissipative factor, D.

The QCM-D™ technique is based on simultaneously measurements of both f and D.

Changes in the conditions of the sensor crystal due to adsorption on the crystal surface

induces a corresponding change in both frequency and dissipation factor. By continuous

measurements of ∆f and ∆D during adsorption, information is obtained about the

adsorption kinetics and the amount of adsorbed matter, as well as viscoelastic properties

of the overlayer. The adsorption of matter onto the crystal is treated as an equivalent

mass change of the crystal itself, and the increase in mass, ∆m, induces a proportional

shift in frequency, ∆f, which was demonstrated by Sauerbrey [87] in 1959:

18

Chapter 3 - Methodology and Theory

nfC

nffv

nfft

m qqqq ∆−=

∆−=

∆−=∆ 2

00 2ρρ

(3-1)

where ρq and νq are the specific density and the shear wave velocity in quartz

respectively, tq is the thickness of the quartz crystal, and f0 the fundamental resonance

frequency (when n=1). However, for this relation to be considered valid, the following

conditions must be fulfilled: i) the adsorbed mass is distributed evenly over the crystal.

ii) ∆m is much smaller than the mass of the crystal itself, and iii) the adsorbed mass is

rigidly attached, with no slip or inelastic deformation in the added mass due to the

oscillatory motion.

The shift in dissipation factor in a liquid environment may be calculated from Stockbridge

relation [90]

ft

D ll

qq πηρ

ρ 21

=∆ (3-2)

where ηl and ρl are the viscosity and density of the fluid, respectively tq and ρq are the

thickness and the density of the quartz plate.

Figure 3.2 Schematic views of the quartz crystal microbalance cell and quartz crystal.

A schematic drawing of the measuring cell is shown in Figure 3.2. The key components

are i) the sensor crystal mounted in a measurement chamber with facilities for batch of

flow measurements in liquid or gas, ii) the drive electronics (relay and signal generator),

and iii) the recording electronics (probe, reference frequency, filter) including data-

19

Chapter 3 - Methodology and Theory handling and software (analogue-to-digital converter and computer). The apparatus used

in this study is a QCM-D device from Q-Sense, Gothenburg, Sweden. AT-cut quartz

crystal oscillators were used, with approximately 100 nm thick gold electrodes

evaporated onto the crystal surface. To minimise the temperature flux from the system,

the surrounding room was temperature controlled, and all solutions were stored in the

same room. The temperature variations in the room were monitored to be in the range of

± 0.5˚C, and the temperature in the chamber was assumed to be the same.

3.3 Near Infrared Spectroscopy (NIR)

William Herschel is credited as the father of near-IR techniques, for his discovery of the

near infrared region as early as 1800. Today, over 200 years later, near infrared

spectroscopy is one of the fastest growing analytical techniques, particularly in the food

and agricultural industries [91, 92]. With recent advances in instrumentation and

multivariate data analysis, the technique has also awoken the attention of the

pharmaceutical industry. The reason for this massive interest is probably a direct result

of its advantages as an analytical tool for quality control. The molar absorptivity of NIR

bands permits operations in the reflectance mode, and hence the measurements can be

made directly on the material itself. The measurements are thus rapid and non-invasive

[93], and there is usually no need for extensive sample preparation. Also, the NIR

spectra contain information on both chemical composition and physical properties of the

sample [94]. This permits not only the identification of compounds, but also total

characterisation of samples and determination of non-chemical parameters.

The near infrared region is found between the visible and middle infrared regions (MIR)

of the electromagnetic spectrum. According to the American Society for Testing and

Materials (ASTM), it is defined as the spectral region spanning 780 - 2526 nm (12820 -

3959 cm-1). Light absorption in this region is primarily due to overtones and

combinations of fundamental vibration bands occurring in the MIR region. This makes

NIR an excellent choice for hydrocarbon analysis, where functional groups such as

methylenic, olefinic and aromatic C-H give rise to various C-H stretching vibrations that

are mainly independent of the rest of the molecule.

In addition to molecular absorption, the NIR spectra are dependent upon several physical

parameters, where the most prominent is scattering from particles. As the particle size

20

Chapter 3 - Methodology and Theory changes it causes a change in the amount of radiation scattered by the sample [95], and

this is reflected in the NIR spectra as a shift of the baseline. A typical representation of

the baseline shift in a system as a consequence of change in particle sizes are shown in

Figure 3.3.

Figure 3.3 Optical density, a sum of scattering and absorption of transmitted light, plotted against

wavelength for several NIR spectra. The system consists of asphaltene particles in model oil

(heptane/toluene 70/30 vol. %) and is measure at defined time intervals after injection of a

chemical. The lowering of the baseline is a measure of decreased scattering as the chemical

disperses the particles.

For slightly lossy dielectric spheres in the Rayleigh limit (r/λ ≤ 0.05), the scattering and

absorption processes contribute separately to the extinction coefficient [96, 97]. That is

abssctot σσσ += (3-3)

where σtot, σsc and σabs are the total, scattering and absorption cross-sections,

respectively. The ratio of scattering to absorption scales with r3, indicating the

importance of particle size on the total light extinction. The relation between optical

21

Chapter 3 - Methodology and Theory density (OD), light intensity (I), particle diameter (N) and particle cross section (σtot) is

given as

totNIIOD σ434.0log 0 =

= (3-4)

where I0 and I are the intensities of incident and transmitted light, respectively. The

effect of multiple scattering is not accounted for in this equation. Details on light

scattering in the near infrared region can be found in the literature [98-100].

The NIR-measurements were performed with a Brimrose AOTF Luminar 2000

spectrometer, equipped with a fibre optic sampling probe for transflectance

measurements (see Figure 3.4). In the study of various chemicals influence on

asphaltene aggregates sizes, the optical density at 1600 nm wavelength was utilised. In

this region the hydrocarbon absorption is minimal, and it is the near-infrared region with

the least noise in the measurements.

Figure 3.4 The near infrared spectrometer setup.

3.4 Nuclear Magnetic Resonance (NMR)

The property of Nuclear Magnetic Resonance (NMR) was first described by Purcell [101]

and Bloch [102] in 1946, work for which they received the Nobel Prize in 1952. Since

then NMR has become a powerful tool in the analysis of chemical composition and

structure [103, 104]. The NMR experiments are performed by immersing atoms in a

static magnetic field (B0), which polarises the sample such that it has a bulk

magnetisation aligned with the direction of the field. In order for this to occur the nuclei

22

Chapter 3 - Methodology and Theory must possess a non-zero spin (e.g., 1H, 2H, 13C, 19F and 31P). An oscillating magnetic

field, in form of a radio frequency (r.f.) pulse, is then applied for a short time orthogonal

to B0 and causes the longitudinal magnetisation to be tipped into the transverse plane.

The absorption or emission of electromagnetic radiation by the nuclear spins causes

transitions between the two energy states, spin-up and spin-down. The specific

frequency at which a given type of nuclei absorbs is given by the Larmor equation:

ω0 = γ ⋅ B0 (3-5)

where ω0 is the Larmor angular frequency, γ the gyromagnetic ratio of the nuclei and B0

the strength of the magnetic field. Since the application of a resonant r.f. pulse disturbs

the spin system, there must subsequently be a process of returning to equilibrium. This

involves exchange of energy between the spin system and its surroundings. Such a

process is called spin-lattice relaxation, and the rate at which equilibrium is restored is

characterised by the spin-lattice or longitudinal relaxation time, T1. The spins do not only

exchange energy with the surrounding lattice, but also among themselves. This is

generally a faster process than spin-lattice relaxation, and is characterised by the spin-

spin relaxation time, T2. The relaxation processes induce a voltage that can be detected

by a suitably tuned coil of wire, amplified, and the signal displayed as the free induction

decay (FID). This gives rise to characteristic spectra, which are functions of several

factors i) the type of nucleus, ii) the chemical environment of the nucleus, and iii) on the

spatial location in the magnetic field if that field is not uniform everywhere.

Pulsed Field Gradient Spin Echo NMR (PFG-SE NMR)

The principle of measuring molecular self-diffusion by NMR is based on the possibility to

label molecules according to their position in the sample by applying a magnetic field

gradient with position-dependent strength. The applied field will change the refocusing in

the spin-echo experiments, which will lead to a reduction in signal intensity if the labelled

molecules have diffused to new positions during the experiment. Self-diffusion

measurements by NMR have been utilised in numerous studies ever since the discovery

of spin echo by Hahn in 1950 [105]. Several new effects on spin echoes were presented,

one of which was the diffusional effect on echo amplitudes in an inhomogeneous

magnetic field. Carr and Purcell [106] provided a more precise theoretical description

four years later, where they also modified the experiment by employing different

magnetic field gradients. This made it possible to measure diffusion.

23

Chapter 3 - Methodology and Theory The spin echo method was significantly improved in the mid sixties with the pulsed field

gradient spin-echo (PFG-SE) technique. McCall et al. [107] are usually credited for the

basic idea published in 1963, while the methodology and theory were presented later on

by Stejskal and Tanner [108]. Several modifications to the technique have been made,

and presently, PFG-SE NMR has evolved into a very useful approach in the studies of

surface and colloid chemistry. The method is non-evasive, relatively fast, and measures

the true molecular self-diffusion coefficients. It provides component resolved information

concerning structural changes, bindings and associated phenomena, as well as sizes and

shapes, from complex mixtures. Hence, the PFG-SE NMR technique offers an alternative

way of obtaining information from, for instance, hydrocarbon mixtures, where typical

light transmission techniques are difficult to use due to the opaqueness.

The Basic 90° - 180° Experiment

In its simplest form the PFG-SE NMR method consists of two radio frequency pulse spin-

echo experiments, with identical magnetic field gradient pulses of magnitude G and

duration δ and time delay ∆ applied, respectively. An initial 90o r.f. pulse produces an

oscillating field B1 perpendicular to B0, while the gradient pulse causes a rapid

precessional phase shift depending on the position of each nucleus in the sample. After a

time τ after the 90o pulse, a 180° pulse is applied, which inverts the phase shift. The

succeeding gradient pulse produces phase compensation, i.e. refocuses the spins. If

nuclei have changed position during ∆ due to diffusion, the refocusing will be incomplete

and consequently the attenuation of the spin echo will decrease. Spins having completed

a change of location, due to Brownian motion during the time period ∆ between both

gradient pulses, will however experience different phase shifts by the two gradient

pulses. As a consequence they are incompletely refocussed and lead to echo decay.

The Stimulated Echo Method (90° - 90° - 90°)

Diffusion experiments are usually facilitated by long spin-lattice (T2) relaxation times and

high gyromagnetic ratios. However, for slow motional processes, chemical exchange or

spin relaxation effects, T2 may in some cases be much smaller than T1, e.g. for large

and/or rigid molecules. When T2 is small, parts of the signal may be lost due to natural

T2- relaxation during ∆. By minimising the time period in which the spins are projected

onto the xy plane, this effect may be limited. This is usually achieved by the stimulated

echo pulse sequence. The experiment utilizes three 90° pulses, where the first pulse

rotates the magnetisation into the xy-plane, after which the spins in various volume

24

Chapter 3 - Methodology and Theory elements lose coherence, and acquire various angles in the rotating frame. The second

pulse stores the memory of the current phase angles in the z-direction, where they are

unaffected by field gradients and relax in the longitudinal direction. The third pulse

restores the phase angles with reversed signs, so that they now precess to form an echo.

The PFG-SE NMR experiments were performed on a Unity Inova 500 MHz spectrometer

and an Oxford magnet equipped with a diffusion probe from DOTY Sci. Inc., USA. The

pulse sequence used for the diffusion measurements was a stimulated echo where the

gradient pulse duration (δ) and the experimental observation time (∆) were kept constant

at 4 and 70 ms, respectively. A sine-shaped gradient was used to minimise the effect of

eddy-currents. The gradient strength (g) was varied in 41 or, in the case when

naphthenic acid had been added, 51 linear steps from 0 to a maximum value chosen so

as to obtain a hundredfold decrease of the signal attenuation.

25

Chapter 4 - Main Results

4 Main Results

This chapter presents a summary of results from the Papers included in this thesis. In

Paper I, a new mechanism involved in the breaking of crude oil emulsions is proposed.

Further investigations of the influence of gas bubbles on the stability of crude oil

emulsions, have resulted in Paper II. This describes a patent on a new method for

breaking of particle stabilised crude oil emulsions by injection of polar gases. The

objective of Paper III is whether or not a “dead” crude oil sample, by recombination with

a gas phase, can recover the emulsion separation properties of the original “live” crude

oil. In the first three Papers the experiments are conducted in a high-pressure separation

rig. In Paper IV the focus is slightly shifted to the surface-active agents involved in

stabilising the water-in-oil emulsions, and the interactions between asphaltenes and

resins are studied using a quartz crystal microbalance. The Paper deals with the

adsorption of these indigenous surfactants on hydrophilic surfaces, individually, through

co-adsorption, or in the form of competing adsorption. Paper V further explores the

interactions between asphaltenes and various surfactants, including synthetic and natural

naphthenic acids, and how they influence the asphaltene aggregate sizes. These studies

are done by near infrared spectroscopy. In the final Paper, Paper VI, the interactions

between asphaltenes and naphthenic acids are studied by nuclear magnetic resonance

and near infrared spectroscopy, and information about size and shape of the asphaltene

aggregates is obtained. Included in this thesis is also the chapter “Demulsifiers in Oil

Industry” from “Encyclopedic Handbook of Emulsion Technology.

4.1 Paper I

One of the largest problems in oil production is the formation of emulsions stabilised by

heavy crude oil components like asphaltenes, resins and waxes. Such problems may in

some cases be solved by means of injections of chemicals or introduction of mechanical

separation facilities. However, the costs of these solutions are normally high and the

search for new and efficient separation tools is important.

The objective of the first Paper was to investigate the effects of separation pressure,

pressure drop and solvency on the stability of crude oil emulsions. A North Sea crude oil

26

Chapter 4 - Main Results was recombined with dry natural gas to a separator pressure of 11 bar. Thereafter the

sample was mechanically pressurised further to 100 bar, or in some cases 182 bar, by a

piston pump connected to the sample cylinder. In some of the experiments the crude oil

was diluted with various amounts of toluene to modify the aromaticity of the oil phase.

The experiments were performed in a high-pressure separation rig, which is further

described in chapter 3.1. In the rig, the fluids are mixed by a pressure drop through

choke valves into a vertical batch separator cell, where the separation of the different

phases are monitored visually.

In the experiments several effects on the separation were observed: i) increased

separation with increasing pressure drop below the separation pressure. This was argued

as owing to gas bubbles that propagate through the emulsion, tearing away stabilising

material from the water/oil interface. ii) Increased pressure drop gave more stable

emulsions for separation above the bubble pressure, and iii) toluene dilution of the crude

oil resulted in less stable emulsions. A higher energy input, due to increased pressure

drop, obviously resulted in smaller water droplets and consequently a slower separation

process. The relation between energy input and droplet size has been shown before by

several authors [109-113]. Also the destabilising effect from diluting the crude oil with

toluene, was as expected. McLean and Kilpatrick [70] showed that as the aromaticity of

the oil phase increased, the asphaltene aggregates were dissolved and the stability of the

emulsions was reduced. Further, the foamability was also affected by the toluene

addition. For increasing content of toluene in the oil phase, the capacity of the system to

form foam decreased as a result of dissolution of stabilising material.

More interesting was the comparison of experiments performed on a recombined oil

phase, with a recombined oil phase that had been degassed (I.e. the recombined oil

phase was depressurised to atmospheric pressure, while allowing the gas phase to

evaporate). The degassed sample was then repressurised mechanically by use of a piston

pump to the original pressure (100 bar). The two types of oil samples were put through

an identical emulsification procedure. The oil was mixed with pressurised formation

water, 35 volume %, by pressure drops through two succeeding choke valves: From 100

to 11 bar and from 11 to the separation pressure in the separator (7 or 1 bar). For the

recombined samples there were a significant foam formation and relatively fast

separation for both separation at 7 and 1 bar. It was interesting to notice that the

experiment with the largest pressure drop over the second choke valve, separated

27

Chapter 4 - Main Results fastest. For the degassed samples there were no foam formation, and both the

separation at 7 and 1 bar were equally slow, as shown in Figure 4-1.

Figure 4-1 Resolution of water vs. time, for water-in-oil emulsions made from recombined samples

and degassed recombined samples at 7 and 1 bar separation pressure.

These results were accounted for by the flotation effect of gas bubbles on the stabilising

material. As the oil phase was depressurised, the solubility of light end molecules

decreased, and a gas phase evolved. The gas phase would then rise through the solution

in the form of bubbles, which could rip off surface-active materials from the water-oil

interface. Paper II deals with this mechanism in further detail.

4.2 Paper II

In order to investigate the influence of flotation upon separation of particle stabilised

water-in-oil emulsions, a series of experiments on different crude oil and model oil

systems were performed. The results led to the development of a patent for the use of a

polar gas as a separation promoter for breaking water-in-oil emulsions. The basic idea is

that the gas phase should be mixed with the water phase at an early stage in the

separation process. In this way the emulsification takes place with an aqueous phase

enriched with dissolved gas. When lowering the pressure in a separator tank, there will

be a release of gas in the form of bubbles, which can enhance the breaking of oil-

continuous emulsions. In the experiments described in this Paper, CO2 was used as the

gas phase.

28

Chapter 4 - Main Results Results from two different North Sea crudes, termed A and B, are shown. Both of these

have been known to give stable water in crude oil emulsions although the stabilising

mechanisms can be different. Crude A is a heavy crude with a high content of

asphaltenes, while crude B is a acidic crude with a high amount of naphthenic acids. In

addition a model system consisting of crude A (1% of A in Exxsol D-80) was tested.

Essential for the discussion is that these samples were run through pressure reductions

where the initial pressure (100 bar) was reduced to the separator pressure 65 bar. A

schematic drawing of the experimental setup is shown in Figure 4-2, and a more

extensive overview of the high-pressure high temperature rig is given in chapter 3.1.

Figure 4-2 Experimental setup. The separator pressure was reduced to 1 bar after 5 minutes.

The emulsions were kept in the vertical separator for 5 minutes, before the final pressure

was adjusted as a gas release from 65 bar to 1 bar. During this period of time the

emulsion undergoes a settling process. The effect of propagating gas bubbles should be

increased if the major part of the water droplets is assembled in a dense packed region.

Figure 4-3 and 4-5 show the separation of water as a function of time for emulsions

made up from crude oil A.

29

Chapter 4 - Main Results

Figure 4-3 Resolution of water vs. time for the dead crude oil A system. The pressure in the

separation cell was reduced from 65 to 1 bar after 5 minutes.

The dispersed aqueous phase was either pure water or water saturated with CO2. For

crude oil A, Figure 4-3 reveals the effect of the pressure gradient over the choke and the

addition of CO2. The effect of CO2 seemed to increase with increased pressure gradient (5

or 20 bar). However, in most of the cases the separation was accelerated by the release

of CO2 after 5 minutes. With a 5 bar pressure gradient there was no significant difference

to the samples containing only pure water. However, the large effect was seen for the

emulsion with a ∆P = 20 bar and an aqueous phase saturated with CO2. For the first 5

minutes, the separator pressure was kept at 65 bar, and the level of separation was low

or almost negligible. Then, as the pressure reduction took place, between 50 and 60 % of

the water phase would separate within 1-2 minutes. After 15 minutes 90 % of the water

had separated. This was a significant result for a crude oil, which has proven to give very

stable emulsions that are resistant to both chemical and mechanical treatment.

30

Chapter 4 - Main Results

Figure 4-4 Resolution of water vs. time for crude oil B. The pressure in the separation cell was

reduced from 65 to 1 bar after 5 minutes.

Figure 4-4 shows the separation sequence for emulsions based on crude oil B.

Characteristic for this system was that some separation, approximately 10 %, would take

place already at 65 bar. However, when the gas was released after 5 minutes the

separation profile changed dramatically. All curves, independent of pressure drops over

the chokes and content of CO2 in the water phase, showed a faster resolution of water.

Hence, the selectivity between the different emulsions was lost. Large effects were seen

both with and without CO2 in the aqueous phase, and with small and larger pressure

gradients over the choke. In these cases, one could not with certainty relate the

increased separability to carbon dioxide release. The model system, where 1 % of crude

oil A was diluted into a paraffinic fluid (Exxsol-D 80) and combined with 40 % water with

and without CO2, is presented in Figure 4-5. The separation level of the model emulsions

was much lower, but also in this case an acceleration of the gas release upon the

separation of water, was clearly seen. Based on the results obtained in the experiments,

two processes are thought to commence upon pressure reduction in a separator tank.

31

Chapter 4 - Main Results

Figure 4-5 Resolution of water vs. time for a model system consisting of 1 % crude oil A in Exxsol

D-80. The pressure in the separation cell was reduced from 65 to 1 bar after 5 minutes.

Proposed mechanisms for breaking of oil-continuous emulsions:

The droplet rupturing effect:

The CO2 dissolved into the aqueous phase (the droplets) will rapidly form small bubbles

upon a pressure reduction. Due to the gravity difference these bubbles propagates

through the emulsified system. When the bubbles leave the water droplet they have to

pass an interface built up by indigenous polar surfactants (asphaltenes and resins). As a

consequence the interfacial film will be ruptured. If the CO2 bubbles carry with them

surface active material from the interface (flotation effect) the time for the interface to

reform will, most likely, be longer than the coalescence time. Hence the system will

break and water and oil phases should appear. Application pressures could be about 60

bar depending on the chemical system and the whole process design.

The film drainage effect:

The CO2 dissolved in the oil phase (the continuous phase) will also rapidly coalesce and

form bubbles upon a pressure reduction. The buoyancy forces cause the bubbles to

propagate through the emulsified system. In doing so they may tear off surface-active

material from the o/w interface described as a flotation effect. This effect should not be

32

Chapter 4 - Main Results specific for CO2 but expected to be common for all oil soluble gases below the bubble

point.

Figure 4-6 Illustration of the proposed effects from CO2 bubbles on water droplets in an oil-

continuous phase: i) The droplet rupturing effect. ii) The film drainage effect.

It was experimentally shown that a polar gas, such as CO2, could accelerate the breaking

of crude oil based emulsions. However, this was not possible for all types of crude oil

emulsions. Presumably it is feasible only for those types of crude oil emulsions, which are

particle stabilised. Also, the use of CO2 will be effective in a gravitation separator and

most effective in a separator of batch type. The emulsion will be held a few minutes in

the separator to settle before the gas pressure in the separator is reduced. However, in a

continuous process, the effect will be much less.

It is well known that CO2 forms gas hydrates at low temperatures and high pressures.

Therefore, it should be pointed out that separation and injection conditions should be far

from the thermodynamic conditions for gas hydrate formation. Dissolved CO2 may also

constitute a danger for corrosion and low pH’s. These conditions must be taken into

account in designing a future process and in the choice of the materials.

4.3 Paper III

The emulsion stability for a “live” crude oil was compared to the emulsions stability of the

same crude oil recombined with, N2, CO2, CH4, C2H6 or a natural gas mixture. Emulsion

stability experiments, where varying amounts of the lighter molecules in the "live" crude

oil had been removed, were also performed. The experiments were thus comprised from

33

Chapter 4 - Main Results the following three types of oil samples: i) “Live” crude oil samples with a bubble point of

15 bar, ii) Samples where the gas phase had been removed from "live" samples by

depressurising to 1 bar, while allowing the gas to evaporate (degassing), and thereafter

repressurised to 15 bar with either N2, CO2, CH4, C2H6 or the natural gas mixture. iii)

Samples that were degassed in the recombination cell to 10 or 1 bar, respectively, and

thereafter mechanically repressurised to 15 bar by use of a piston pump and no addition

of gas.

The oil samples were transferred into the sample cylinder on the high-pressure high

temperature rig, described in chapter 3.1, and further pressurised to 20 bar by use of a

piston pump. To create emulsions, the oil samples were streamed together with synthetic

formation water through a choke valve, while varying the pressure drop and separation

pressure. The decomposition of the resulting emulsion and foam layer could thereafter be

monitored visually in the vertical high-pressure separation cell. As a result, the

separation properties of the water-in-crude oil emulsions from the different recombined

samples and the “live” crude oil could be compared.

The results from experiments performed at oil type i) and ii) showed the following

trends: Water-in-oil emulsions produced from "live" North Sea crude oil, generally

separated faster and more complete than emulsions based on recombined samples of the

same crude oil. An example of such a water resolution chart is shown in Figure 4-7.

Increased water content or smaller pressure drop into the separator, resulted in faster

and more complete separation of the emulsions for both "live" and recombined samples.

It was also noted that the height of the foam layer increased when reducing the water

content from 60 to 40 volume %.

34

Chapter 4 - Main Results

Figure 4-7 Resolution of water vs. time for “live” and recombined oil samples. Separation pressure,

pressure drop and water content were 15 bar, 5 bar and 60 volume %, respectively.

Experiments performed on oil type 3, i.e. oil samples with varying content of light

molecules, can be concluded as follows: As expected the "live" (15 bar) sample gave the

highest amount of foam for water content of both 60 and 40 volume %. A smaller

amount was obtained for the 10 bar sample and none for the sample degassed to 1 bar.

The emulsion stability for the mechanically recombined crude oil samples seemed to

depend on the degassing pressure of the "live" sample, i.e. the content of gas present in

the oil phase. Samples with the lowest gas content gave, probably as a result of higher

viscosity, a less complete emulsification. This would in turn create a higher number of

relatively large droplets, which separated within the first few minutes, while the rest

emulsion maintained the same stability as for the samples with higher amount of gas

remaining. As for the other oil samples, the amount of water influenced the emulsion

stability together with the pressure gradient over the choke. Smaller water content (40

%) and large ∆P over the choke (19 bar) gave higher emulsion stability in comparison

with 60 % of water and 5 bar pressure drop. Most likely the drop size distribution was

quite different for these samples with much smaller droplets for 40 volume % of water

and high ∆P.

35

Chapter 4 - Main Results 4.4 Paper IV

The adsorption of stabilising material onto hydrophilic surfaces was investigated in Paper

IV. To do this, the adsorption of asphaltenes and resins onto a hydrophilic gold surface,

was measured as a function of bulk concentration. The measurements were performed by

a quarts crystal microbalance with dissipation measurements (QCM-D™), which is

described in chapter 3.2. This device allows for simultaneous measurements of

frequency, f, and energy dissipation factor, D. The change in frequency is related to the

mass adsorbed onto the surface of the sensor crystal, and from the change in dissipation

factor, information about the interfacial processes can be resolved.

Figure 4-8. Adsorption isotherms for resin adsorption onto a hydrophilic gold surface as a function

of resin concentration in pure n-heptane.

The results showed that the resins in pure heptane adsorb onto a gold surface, and pack

into a compact monolayer (Figure 4-8). However, the resins showed no tendency to

aggregate on the surface. With increasing amount of aromaticity in the solvent, the

adsorbed quantity decreased, and was practically zero in pure toluene. This was related

to an increased solvency of the resins. The asphaltenes in heptane/toluene mixtures, or

pure toluene, adsorbed to a larger extent (Figure 4-9). The adsorption was higher than

observed for typical non-associating polymers, which indicated adsorption of aggregates.

At lower concentrations the asphaltenes formed a rigid layer. When higher concentrations

were injected it was possible to obtain further adsorption, which was related to the

strong tendency of aggregation of asphaltenes in bulk solution. Supposing this multilayer

adsorption also occurs onto water droplets dispersed in oil, it may result in a thick barrier

that stabilise the droplets from coalescence.

36

Chapter 4 - Main Results Desorption studies showed that resins were not able to desorb pre-adsorbed asphaltenes

from the surface. Neither did they adsorb onto the asphaltene-coated surface. On the

other hand, resins and asphaltenes associated in bulk liquid, and the adsorption from

mixtures containing both resins and asphaltenes was markedly different to that observed

for the pure components. It was therefore concluded that preformed resin/asphaltene-

aggregates adsorb to the surface.

Figure 4-9 Adsorption isotherm for asphaltene adsorption onto a hydrophilic gold surface as a

function of asphaltene concentration in pure toluene.

The irreversibly adsorbed amount for a crude oil solution was smaller than for the

asphaltene and resin mixture but quite similar to that of the separate fractions. When

effects from other constituents like paraffin and wax were absent, the resin and

asphaltene molecules arranged in a different way in the adsorbed layer. When paraffin

and wax was present they could be incorporated in the adsorbed layer, or affected the

interaction forces in the bulk of the crude.

4.5 Paper V

Resins are usually thought to function as a dispersant of asphaltenes in crude oil. In

order to hinder asphaltene deposition, the petroleum industry injects large volumes of

chemicals into reservoirs and pipelines. These chemicals are supposed to imitate the

37

Chapter 4 - Main Results resin function, by dispersing the asphaltenes in the hydrocarbon mixture. The size of the

asphaltene aggregates also influence the capacity to form emulsions, where the optimum

size for stabilising, depends upon the size of the water drops. That is, changing the size

of the asphaltene aggregates beyond the optimum size region, may also prevent

emulsion formation. In Paper V, near infrared (NIR) spectroscopy was introduced as a

potent tool for studying the effect of chemicals in dissolution of asphaltene aggregates.

As described in chapter 3.3, the NIR technique is sensitive to the size of scattering

particles. Thus, the change in size of the asphaltene aggregates could be probed as a

function of time and additive concentration.

Different chemicals with various functional groups were employed in the experiments;

fatty alcohols and fatty amines, which are typical ingredients in asphaltene inhibitors, as

well as a commercial inhibitor designed to inhibit asphaltene precipitation. In addition,

another group of indigenous components found in crude oil, namely naphthenic acids

were incorporated in the experimental matrix.

The experiments were performed by continuously measuring the change in scattering at

1600 nm wavelength, upon addition of chemicals, in a solution of asphaltenes in

heptane/toluene (70/30 by volume). At that aromatic/paraffinic ratio, the asphaltenes

were expected to form rather large aggregates, and any effect on the size should be easy

detectable. In Figure 4-11, the effect of increasing concentration of a polydisperse

naphthenic acid on the aggregate size is shown. The results showed a clear decrease in

scattering as a function of time after the acid was introduced, i.e. the aggregate sizes

decreased. As more concentrated solutions of acid was injected, the scattering decreased

more rapidly as a function of time.

38

Chapter 4 - Main Results

-0.030

-0.025

-0.020

-0.015

-0.010

-0.005

0.000

0 200 400 600 800 1000 1200Time [min]

Optica

l densi

ty

0.125 wt%

No additive

1.25 wt%

3.25 wt%

6.25 wt%

12.5 wt%

Figure 4-10 NIR scattering measurements at 1600 nm for 0.125 wt% asphaltenes in a 70/30 by

volume n-heptane/toluene mixture with crude naphthenic acid (CNA) added in various

concentrations.

When comparing the various naphthenic acids, the synthesised monodisperse acids

showed the largest influence upon the asphaltene aggregates, the polydisperse

naphthenic acids seemed to affect the state of the asphaltenes only to a minor extent.

The other amphiphiles, showed a varying effect on the disintegration of the asphaltenes.

In all cases inhibitor A, the commercial mixture, gave the most efficient treatment.

The oil phases consisting of mixtures of heptane, toluene, asphaltenes and various

chemicals, were also subjected to an emulsification with tap water, 80/20 by volume. The

mixing was done with an Ultra Turrax T25 rotor emulsifier at 22500 rpm for 30 seconds.

The stability of the resulting emulsions was thereafter measured with a critical electric

field emulsion stability devise (Ecrit), which measures the necessary electric field one

must apply in order to break the emulsion. A further description of the specific device

and related theory is given by Aske et al. [114]. The results from the Ecrit experiments

showed that all the emulsions based on oil phases containing additives such as

naphthenic acids or other amphiphiles, gave unstable emulsions. Reference samples

containing only asphaltenes in heptane and toluene were noticeably more stable. This

may indicate that the additives dispersed the asphaltene aggregates to such a degree

that they were unable to reach the water-oil interface and facilitate stable emulsions.

39

Chapter 4 - Main Results 4.6 Paper VI

In Paper V it was shown that addition of naphthenic acids to solutions with asphaltene

aggregates, appeared to disperse the asphaltene aggregates into smaller sizes. This was

thought to occur as a consequence of acid-base interactions between naphthenic acids

and asphaltene. PFG-SE NMR (pulsed field gradient-spin echo nuclear magnetic

resonance) measurements were combined with NIR (near infrared) spectroscopy to

further evaluate potential interactions between asphaltenes and naphthenic acids. The

experiments were run with to types of asphaltenes, one extracted from an acidic crude

(asphaltene 1) and one from a neutral crude (asphaltene 2). The naphthenic acids

employed in the experiments were synthetic monodisperse acids. A concentration series

with asphaltenes in pure toluene was also prepared and studied, in order to obtain

information about self-association of the asphaltene molecules.

PFG-SE NMR (described in chapter 3.4) measurements of the concentration series of

asphaltenes 1 dissolved in toluene-d8 are presented in Figure 4-12. The median diffusion

coefficient of the asphaltenes decreased as a function of increased asphaltene

concentration. Östlund et al. [115] have shown that the obstruction effect in asphaltenic

systems is large, due to the asphaltenes having a disc-like structure. However, the

decrease observed in this system was significantly larger than previously reported. It was

thus likely that the asphaltenes investigated were not only subjected to obstruction, but

also to self-association with an onset of flocculation at 0.1 wt-% asphaltenes.

40

Chapter 4 - Main Results

Figure 4-11 The median diffusion coefficients are displayed as a function of the asphaltene

concentration ( ). Also included are the calculated diffusion coefficients of the asphaltene

aggregates ( ). The calculated values of the diffusion of the asphaltene aggregates ( ) are also

shown in this Figure. The full line illustrates the decrease in the diffusion coefficients that was

expected only due to obstruction (under the assumption that the micelles are monodisperse and

oblate shaped with an axial ratio of 1:20).

In order to study systems containing both asphaltenes and naphthenic acids, both NIR

and PFG-SE NMR were employed. The NIR experiments were performed upon systems

where the asphaltenes were slightly above the precipitation point, as opposed to the

PFG-SE NMR experiments where the systems were below this point. When samples

containing both asphaltenes and naphthenic acid were studied by PFG-SE NMR, it was

observed that the entire signal from 5- β(H)-cholanoic acid (CHOL) appeared at the same

frequency (0.7-2.1 ppm) as the signal from the asphaltenes. The complete overlap of the

signals complicated the evaluation of the samples containing CHOL. 1-

41

Chapter 4 - Main Results naphthalenepentanoic acid, decahydro- (2C4), fortunately had an additional peak at 4

ppm, which made it possible to study the diffusion of 2C4 without any contribution from

the asphaltenes. It was observed that the echo decay of 2C4 was biexponential in the

presence of both asphaltene 1 and asphaltene 2, which indicated that there were

monomeric acid as well as associated acid in the samples. When evaluating the echo

decay arising from combined signals, the fit of the experimental data using a Levenberg-

Marquardt algorithm was seen to give reasonable results. The fitted results were verified

by Monte Carlo simulations [116] and the program CORE [117, 118].

It was interesting to note from the results shown in Figure 4-13 that the diffusion of

asphaltene 2 decreased in all cases independently of which naphthenic acid that had

been added. This indicated that both CHOL and 2C4 interacted with asphaltene 2. The

diffusion coefficient of asphaltene 1, on the other hand did not change and. Thus, it

appeared as if there were no or only weak interactions between the naphthenic acids and

asphaltenes of type 1.

Figure 4-12 The results from samples containing naphthenic acid and asphaltenes. ( ) corresponds

to the diffusion of the naphthenic acid (0.5 or 2.4 wt-% of CHOL alternatively 2C4) while ( )

corresponds to the diffusion of asphaltene 1 (A1) or asphaltene 2 (A2). The diffusion of only

asphaltene 1 or 2 in toluene-d8 (reference samples) has been included. Frames have been put

around the diffusion coefficients from asphaltenes of the same kind (A1 or A2).

42

Chapter 4 - Main Results The NIR measurements (Figure 4-13), where the asphaltene particle size was followed as

a function of time after addition of naphthenic acid, supported these results. It was

shown that the particle size was reduced significantly more for asphaltene 2 than for

asphaltene 1, upon addition of both CHOL and 2C4.

Figure 4-13 The change in optical density (scattering) of asphaltene 1 (A1) and asphaltene 2 (A2)

is displayed as function of time after addition of naphthenic acid (CHOL or 2C4). The spectrum at

time = 0 was used as reference and has been subtracted from the subsequent spectra, thus

eliminating the contribution from absorption to the optical density.

43

Chapter 5 - Summary and Conclusions

5 Summary and Conclusions

Studies of "live" crude oil emulsions in a high-pressure separation rig have led to the

proposal of two new mechanisms for destabilisation of water-in-oil emulsions. Increased

separation efficiency was observed for water-in-crude oil emulsions, when gas bubbles

propagated through the mixture due to a pressure drop below the bubble point of the oil

phase into a vertical separator. These results were accounted for by a flotation effect

from gas bubbles on the stabilising material at the water-oil interface. Separation

experiments were also performed on pressurised dead crude and model oil systems,

where the flotation effect was produced through gas release from a water phase

saturated with CO2 gas. The effect is thought to occur for particle stabilised water-in-oil

emulsions. The use of flotation of stabilising material as a separation tool is thought to be

most effective in gravitational separators of batch type.

The separation properties of a "live" crude oil were compared to crude oil samples

recombined with various gases to pressures equal to the "live" samples. The results

showed that water-in-oil emulsions produced from the "live" North Sea crude oil samples,

generally separated faster and more complete, than emulsions based on recombined

samples of the same crude oil.

The adsorption of asphaltenes and resins onto a hydrophilic gold surface was investigated

by a quarts crystal microbalance with dissipation measurements (QCM-D™). The results

showed that resins in pure heptane adsorb onto a hydrophilic surface, and pack into a

compact monolayer. Asphaltenes in heptane/toluene mixtures, or pure toluene, adsorbed

to a larger degree than the resins. The adsorption was higher than observed for typical

non-associating polymers indicating aggregate adsorption. Desorption studies showed

that resins were unable to desorb pre-adsorbed asphaltenes from the surface. Neither did

they adsorb onto the asphaltene-coated surface. However, mixtures of resins and

asphaltenes associated in bulk liquid and preformed resin/asphaltene-aggregates

adsorbed to the surface.

Near infrared (NIR) spectroscopy was introduced as a potent tool for studying the effect

of different chemicals in dissolving asphaltene aggregates. When comparing the effect

from various naphthenic acids, synthesised monodisperse acids showed a reduction of

44

Chapter 5 - Summary and Conclusions size of the asphaltene aggregates, whereas the more polydisperse naphthenic acids

seemed to affect the state of the asphaltenes only to a minor extent. Other amphiphiles

such as amines and alcohols, showed a varying effect on the disintegration of the

asphaltenes.

Asphaltenes from two different oil types were studied upon addition of two kinds of

naphthenic acids by employing PFG-SE NMR (pulsed field gradient spin echo nuclear

magnetic resonance) and NIR (near infrared) spectroscopy. The results implied that there

were interactions between the asphaltenes and the acids. The dispersing effect of the

naphthenic acids on the asphaltenes was also evaluated, and it appeared as if the

effectiveness of the acids depended on the asphaltene type. Furthermore, a

concentration series of one of the asphaltenes was prepared, and a dramatic decrease in

diffusion coefficients upon increased concentration implied that the asphaltenes began to

self-associate at concentrations above 0.1 wt-% of asphaltenes in toluene-d8. When

comparing the decrease of the diffusion coefficients with theory, it appeared likely that

the asphaltenes were oblate shaped aggregates with an axial ratio of approximately

1:20.

45

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